# Riley Exploration Permian, Inc.: Form 10-K for the period ended Dec 31, 2014

- Company: [Riley Exploration Permian, Inc.](/companies/repx.md) (CIK 1001614)
- Form: 10-K
- Filed: 2015-03-30
- Accepted by EDGAR: Mar 30, 2015, 16:37 ET
- Period: 2014-12-31
- Accession: 0001140361-15-013485
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1001614/000114036115013485/form10k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1001614/000114036115013485/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2014-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Operating income | 12 months, 2014-01-01 to 2014-12-31 | −$739.0k | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2014-01-01 to 2014-12-31 | $88.0k | us-gaap:InterestExpense |
| Income tax | 12 months, 2014-01-01 to 2014-12-31 | $6.0k | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2014-01-01 to 2014-12-31 | −$788.0k | us-gaap:NetIncomeLoss |
| Diluted shares (weighted) | 12 months, 2014-01-01 to 2014-12-31 | 60,849,931 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2014-01-01 to 2014-12-31 | $6.6m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2014-01-01 to 2014-12-31 | $282.0k | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2014-12-31 | $35.0k | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2014-12-31 | $2.1m | us-gaap:AssetsCurrent |
| Total assets | at 2014-12-31 | $37.0m | us-gaap:Assets |
| Current liabilities | at 2014-12-31 | $2.0m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2014-12-31 | $4.9m | us-gaap:Liabilities |
| Long-term debt | at 2014-12-31 | $824.0k | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2014-12-31 | $65.0k | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2014-12-31 | $32.2m | us-gaap:StockholdersEquity |

## Business

As filed, 37,821 characters.

### History of the Company

The Company was initially organized in Utah in 1916 under a name later changed to Onasco Companies, Inc. In 1995, the Company changed its name from Onasco Companies, Inc. by merging into Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this purpose. At the Company’s Annual Meeting held on June 11, 2011, the stockholders of the Company approved an Agreement and Plan of Merger adopted by the Company’s Board of Directors which provided for the merger of the Company into a wholly-owned subsidiary formed in Delaware for the purpose of changing the Company’s state of incorporation from Tennessee to Delaware. The merger became effective on June 12, 2011 and the Company is now a Delaware corporation.

### OVERVIEW

The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of oil exploration and production is in Kansas. The Company’s primary area of natural gas production had been the Swan Creek Field in Tennessee. The Company sold all its oil and gas leases and producing assets in Tennessee on August 16, 2013.

The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a 65-mile intrastate pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee. The Company sold all its pipeline-related assets on August 16, 2013.

The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) operates treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity.

The Company also had a management agreement with Hoactzin Partners, L.P. (“Hoactzin”) to manage Hoactzin’s oil and gas properties in the Gulf of Mexico offshore Texas and Louisiana (See below, “4. Management Agreement with Hoactzin”). This management agreement expired on December 18, 2012. Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He is also the sole shareholder and controlling person of Dolphin Mgmt. Services, Inc., the general partner of Dolphin Offshore Partners, L.P., which is the Company’s largest shareholder.

### General

### 1\. The Kansas Properties

The Company’s operated properties in Kansas are located in central Kansas and as of December 31, 2014 include 196 producing oil wells, 16 shut-in wells, and 37 active disposal wells (the “Kansas Properties”). The Company’s technical management and staff have a great deal of Kansas exploration and production experience. The Company has onsite production management and field personnel working out of the Hays, Kansas office.

The leases for the Kansas Properties provide for a landowner royalty of 12.5%. Some wells are subject to an overriding royalty interest from 0.5% to 9%. The Company maintains a 100% working interest in most of its wells and undrilled acreage in Kansas. The terms for most of the Company’s newer leases in Kansas are from three to five years.

During 2014, the Company drilled 9 gross wells and completed 1 well that was drilling at the end of 2013. All of these wells were operated by the Company and the Company has a working interest of 100% in each well. Of the 9 wells drilled in 2014, 4 of the wells were completed as producing wells.

All of the Company’s current reserve value, production, oil and gas revenue, and future development objectives result from the Company’s ongoing interest in Kansas. By using 3-D seismic evaluation on the Company’s existing locations, the Company has historically added proven direct offset locations and will continue using 3-D seismic evaluation techniques in the future.

### A. Kansas Ten Well Drilling Program

On September 17, 2007, the Company entered into a ten well drilling program with Hoactzin, consisting of three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Program”). Under the terms of the Program, Hoactzin paid the Company $0.4 million for each producing well and $0.25 million for each dry hole. The terms of the Program also provided that Hoactzin would receive all the working interest in the producing wells, and would pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses, referred to as a management fee. The fee paid to the Company by Hoactzin would increase to 85% of its working interest revenues net of operating expenses when net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”). The Payout Point was reached effective with production in February 2014, at which time the management fee for the Program increased from 25% to 85%.

In 2014, the wells from the Program produced total gross production of 12.1 MBbl of which the revenues from 8.6 MBbl were net to the Company. During the 4th quarter of 2014, total gross production from these wells averaged 31 barrels per day, of which the revenues from 23 barrels per day were net to the Company.

The reserve information for the parties’ respective Ten Well Program interests as of December 31, 2014 is indicated in the table below. Reserve reports are obtained annually and estimates related to those reports are updated upon receipt of the report. These calculations were made using commodity prices based on the twelve month arithmetic average of the first day of the month price for the period January through December 2014 as required by SEC regulations. The table below reflects values realized at a price of $88.34 per barrel which was used in the December 31, 2014 reserve report. In addition, the table below reflects achievement of the Payout Point and conversion of the Company’s interest to an 85% interest in February 2014.

### Reserve Information for Ten Well Program Interest as of December 31, 2014

|  | Barrels Attributable to Party’s Interest MBbl | Undiscounted Future Cash Flows Attributable to Party’s Interest (in thousands) | Present Value of Future Cash Flows Discounted at 10% Attributable to Party’s Interest (in thousands) |
| --- | ---: | ---: | ---: |
| Tengasco | 117.3 | $6,695 | $2,917 |
| Hoactzin | 20.7 | $1,182 | $515 |

The Hoactzin reserves were estimated based on Tengasco reserves as of December 31, 2014.

### B. Kansas Production

The Company’s gross oil production in Kansas decreased by 18 MBbl from 204 MBbl in 2013 to 186 MBbl in 2014. This decrease was primarily the result of natural declines from higher 2013 production levels that had resulted from drilling and polymers performed during 2011 and the first half of 2012. Approximately 11 MBbl of the 186 MBbl in 2014 were related to production from the 5 new wells completed during 2014.

The capital projects undertaken by the Company in 2014 were initially funded by borrowings from the Company’s credit facility. However, these additional borrowings under the Company’s credit facility were repaid by December 31, 2014 through use of the Company’s operating cash flows.

### 2\. The Tennessee Properties

In the early 1980’s Amoco Production Company owned numerous acres of oil and gas leases in the Eastern Overthrust in the Appalachian Basin, including the area now referred to as the Swan Creek Field. In the mid-1980’s, however, development of this field was cost prohibitive due to a decline in worldwide oil and gas prices and the high cost of constructing a pipeline to deliver gas to the closest market. In July 1995, the Company acquired the Swan Creek leases and began development of the field. In 2001, the Company completed construction of a 65 mile pipeline from the Swan Creek Field to several meter stations in Kingsport, Tennessee.

The Company evaluated in recent years whether continued development would add additional reserves and the likelihood of realizing additional revenues from transportation of third party gas through the Company’s pipeline assets. The Company determined that current wells would be able to produce the remaining oil and gas reserves and that the Company was unable to attract any additional third party gas without substantial capital investment. As a result, the Company elected to sell its Swan Creek oil and gas assets and its pipeline assets and focus on its oil production from its Kansas Properties.

On March 1, 2013, the Company entered into an agreement with Swan Creek Partners LLC to sell all of the Company’s oil and gas leases and producing assets in Tennessee as well as the Company’s pipeline assets for $1.5 million. The Company closed this sale on August 16, 2013.

The associated revenues and expenses net of taxes of the Company’s pipeline assets have been classified as discontinued operations in the Statements of Operations for the years ended December 31, 2012 and 2013. As the Swan Creek oil and gas assets represented only a small portion of the Company’s full cost pool, the associated revenues and expenses were classified in continuing operations for the years ended December 31, 2012 and 2013.

During 2013, prior to the closing of the sale of the Tennessee oil and gas assets, the Company had 14 producing gas wells and 6 producing oil wells in the Swan Creek Field. Gross gas production volumes from the Swan Creek Field during 2013 until the sale of the properties averaged approximately 226 Mcfd compared to 216 Mcfd produced during year ended December 31, 2012. Gross oil sales volumes from the Swan Creek field during 2013 until the sale of the properties averaged approximately 16.7 BOPD compared to approximately 13.4 BOPD produced during the year ended December 31, 2012.

### 3\. Manufactured Methane Facilities

On October 24, 2006, the Company signed a twenty-year Landfill Gas Sale and Purchase Agreement (the “Agreement”) with predecessors in interest of Republic Services, Inc. (“Republic”). The Company assigned its interest in the Agreement to MMC. The Agreement provided that MMC would purchase the entire naturally produced gas stream being collected at the Carter Valley municipal solid waste landfill owned and operated by Republic in Church Hill, Tennessee and located about two miles from the Company’s pipeline. The Company’s pipeline was sold on August 16, 2013. The Company installed a proprietary combination of advanced gas treatment technology to extract the methane component of the purchased gas stream. The Company constructed a pipeline to deliver the extracted methane gas to the Company’s then existing pipeline (the “Methane Project”).

MMC declared startup of commercial operations of the Methane Project on April 1, 2009. The total cost for the Methane Project through startup, including pipeline construction, was approximately $4.5 million.

On August 27, 2009, the Company entered into a five-year fixed price gas sales contract with Atmos Energy Marketing, LLC, (“AEM”) in Houston, Texas, a nonregulated unit of Atmos Energy Corporation (NYSE: ATO) for the sale of the methane component of landfill gas produced by MMC at the Carter Valley Landfill. The agreement provided for the sale of up to 600 MMBtu per day. The contract was effective beginning with September 2009 gas production and ended July 31, 2014. The agreed contract price of over $6 per MMBtu was a premium to the then current five-year strip price for natural gas on the NYMEX futures market.

In April 2011, MMC purchased from Parkway Services Group of Lafayette, Louisiana a Caterpillar genset which was delivered in late 2011 and installed at the plant site for generation of electricity. Total cost of the generator including installation and interconnection with the power grid was approximately $1.1 million.

On January 25, 2012, MMC commenced sales of electricity generated at the Carter Valley site. The electricity generated is sold under a ten year firm price contract with Holston Electric Cooperative, Inc., the local distributor, and Tennessee Valley Authority through TVA’s Generation Partners program. That program accepted generated renewable power up to 999KW; MMC’s generation equipment is rated at 974 KW to maximize revenues under the favorable electricity pricing under the Generation Partners program. The price provision under this contract pays MMC the current retail price charged monthly to small commercial customers by Holston Electric Cooperative, plus a “green” premium of 3 cents per kilowatt hour (KWH). Current price paid to MMC is approximately $.129 per KWH. In December 2013, the contract was extended by agreement between the Company, Holston Electric Cooperative, and TVA for an additional ten years beginning in January 2022 at the current price rate less the three-cent “green” premium. A one-eighth royalty on electricity revenues is paid to the landfill owner.

During 2013, the Methane Project was online approximately 29% of the time resulting in gas sales net revenues net of royalty of $117,000 and the electric generation was online approximately 27% of the time resulting in electric sales net revenues of $263,000. The significant downtime during 2013 was primarily a result of consistent high levels of oxygen included in the gas coming from the landfill, causing the equipment to shut down until lower oxygen levels on a consistent basis were achieved. As result of this significant down time, the Company reconfigured the fuel supply, added some additional electric generation related equipment, and began an electric generation only program at the Carter Valley site. The cost of the reconfiguration and addition equipment was approximately $274,000 and was operational in late February 2014. During 2014, the electric generation was online approximately 56% of the time resulting in electric sales net revenues of approximately $524,000. Approximately $518,000 of the 2014 revenues were realized during the period March 2014 through December 2014 during which the electric generation was online approximately 66% of the time.

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program (the “Program”), pursuant to a separate agreement with the Company was conveyed a 75% net profits interest in the Methane Project. Because the Payout Point was reached in February 2014 as described above, Hoactzin’s net profits interest in the Methane Project has decreased to 7.5%. The agreed method of calculation of net profits takes into account specific costs and expenses as well as gross gas revenues for the project. As a result of the startup costs, ongoing operating expenses, and reduced production levels discussed above, no net profits as defined have been realized during the period from the project startup in April, 2009 through December 31, 2014 for payment to Hoactzin under the net profits interest. All payments applied to reaching the Payout Point have been generated from the Program.

### 4\. Management Agreement with Hoactzin

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As part of the consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. The Management Agreement expired on December 18, 2012. The Company has entered into a transition agreement with Hoactzin whereby the Company will no longer perform operations, but will administratively assist Hoactzin in becoming operator of record of these wells and administratively assist Hoactzin in the transfer of the corresponding bonds from the Company to Hoactzin. This assistance is primarily related to signing the necessary documents to effectuate this transition. Hoactzin and its controlling member are indemnifying the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is the operator of record on certain of these wells. As of the date of this Report, the Company continues to administratively assist Hoactzin with this transition process. The transition was anticipated to be completed by this time, and the transition agreement provides that the Company may hold Hoactzin’s drilling programs funds in suspense until the transition process has been completed. As of December 31, 2014, the Company was holding approximately $590,000 of such funds pending completion of the transition process.

During the term of the Management Agreement, the Company became the operator of certain properties owned by Hoactzin. The Company obtained from IndemCo, over time, bonds in the face amount of approximately $10.7 million for the purpose of covering plugging and abandonment obligations for Hoactzin’s operated properties located in federal offshore waters in favor of the BSEE, as well as certain private parties. In connection with the issuance of these bonds the Company signed a Payment and Indemnity Agreement with IndemCo whereby the Company guaranteed payment of any bonding liabilities incurred by IndemCo. Dolphin Direct Equity Partners, LP also signed the Payment and Indemnity Agreement, thereby becoming jointly and severally liable with the Company for the obligations to IndemCo. Dolphin Direct Equity Partners, L.P. is a private equity fund controlled by Peter E. Salas that has a significant economic interest in Hoactzin. Hoactzin had provided $6.6 million in cash to IndemCo as collateral for these potential obligations. As of May 15, 2014, all bonds issued by IndemCo and subject to the Payment and Indemnity Agreement have been released by the BSEE and have been cancelled by IndemCo. Accordingly, the exposure to the Company under any of the now cancelled IndemCo bonds or the indemnity agreement relating to those now cancelled bonds has decreased to zero.

As part of the transition process, Hoactzin secured new bonds from Argonaut Insurance Company to replace the IndemCo bonds. Also as part of the transition to Hoactzin becoming operator of its own properties, right-of-use and easement (“RUE”) bonds in the amount of $1.55 million were required by the regulatory process to be issued by Argonaut in the Company’s name as current operator. Hoactzin is in the process of transferring these RUE bonds from the Company to Hoactzin. Hoactzin and Dolphin Direct signed an indemnity agreement with Argonaut as well as provided the required collateral for the new Argonaut bonds, including 100% cash collateral for the RUE bonds issued in the Company’s name. The Company is not party to the indemnity agreement with Argonaut and has not provided any collateral for any of the Argonaut bonds issued. When the transfer of the RUE’s and associated bonds is approved, the transfer of operations to Hoactzin would be complete and the Company’s involvement in the Hoactzin properties will be ended.

As operator, the Company routinely contracted in its name for goods and services with vendors in connection with its operation of the Hoactzin properties. In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name. During late 2009 and early 2010, Hoactzin undertook several significant operations, for which the Company contracted in the ordinary course. As a result of the operations performed in late 2009 and early 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet. Payables related to these past due and ongoing operations remained outstanding at December 31, 2014 and 2013 in the amount of $159,000 and $327,000, respectively. The decrease in payables was due to payment by Hoactzin of invoices received by the Company from IndemCo related to bond premiums, which invoices have been paid by Hoactzin in full and the IndemCo bonds cancelled. The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of December 31, 2014 and 2013 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”. Since the second quarter of 2012, the only increase in the Hoactzin-related payables that have been recorded on the Company’s Consolidated Balance Sheets relate to the IndemCo bond premiums. As all the IndemCo bonds have been cancelled, the outstanding balance of $159,000 should not increase in the future. However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012. Based on these circumstances, the Company has elected to establish an allowance in the amount of $159,000 for the balances outstanding at December 31, 2014 and 2013. This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”. The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159 and $257” are $0 and $168,000 at December 31, 2014 and 2013, respectively.

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties. This action calls for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011. In the 4th quarter of 2012, the Company filed an administrative appeal with the Interior Board of Land Appeals (“IBLA”) of this action in order to attempt to significantly reduce the civil penalty. This appeal required a fully collateralized appeal bond to postpone the payment obligation until the appeal was determined. The Company posted and collateralized this bond with RLI Insurance Company. If the bond was not posted, the appeal would have been administratively denied and the order to the Company as operator to pay the $386,000 penalty would have become final. On June 23, 2014, the IBLA affirmed the civil penalty without reduction. On September 22, 2014, the Company sought judicial review of the June 23, 2014 agency action in the federal district court in the Eastern District of Louisiana at New Orleans. While the civil penalty could ultimately be reduced in the judicial review process, as a result of the determination by the IBLA, the Company recorded a liability of $386,000 in the Company’s Consolidated Balance Sheets under “Accrued and other current liabilities” and an expense in its Consolidated Statements of Operations under “Production costs and taxes” for the year ended December 31, 2014. In the event any portion of the civil penalty is affirmed, the Company expects to seek reimbursement of such penalty from Hoactzin, pursuant to the terms of the Management Agreement. However, there can be no assurances that the Company would be successful in such a claim.

No funds have been advanced by the Company to pay any obligations of Hoactzin. No borrowing capability of the Company has been used by the Company in connection with its obligations under the Management Agreement, except for those funds used to collateralize the appeal bond with RLI Insurance Company.

### 5\. Other Areas of Development

Although focused on development of its current Kansas holdings, the Company will continue to review potential transactions involving producing properties and undeveloped acreage in Kansas and the surrounding states.

### Governmental Regulations

The Company is subject to numerous state and federal regulations, environmental and otherwise, that may have a substantial negative effect on its ability to operate at a profit. For a discussion of the risks involved as a result of such regulations, see, “Effect of Existing or Probable Governmental Regulations on Business and Costs and Effects of Compliance with Environmental Laws” hereinafter in this section.

### Principal Products or Services and Markets

The principal markets for the Company’s crude oil are local refining companies. At present, crude oil produced by the Company in Kansas is sold at or near the wells to Coffeyville Resources Refining and Marketing, LLC (“Coffeyville Refining”) in Kansas City, Kansas and to National Cooperative Refinery Association (“NCRA”) in McPherson, Kansas. Both Coffeyville Refining and NCRA are solely responsible for transportation to their refineries of the oil they purchase. The Company may sell some or all of its production to one or more additional refineries in order to maximize revenues as purchases prices offered by the refineries fluctuate from time to time.

Gas from the Company’s Methane Facility has been sold at the tailgate of the plant to Atmos Energy Marketing. The contract with Atmos expired in July 2014. Electricity generated at the site is sold to Holston Electric Cooperative. The contract with Holston Electric had a ten year initial commitment and has been extended for an additional ten years as described above. The contract will expire in January 2032.

### Drilling Equipment

The Company does not currently own a drilling rig or any related drilling equipment. The Company obtains drilling services as required from time to time from various drilling contractors in Kansas.

### Distribution Methods of Products or Services

Crude oil is normally delivered to refineries in Kansas by tank truck. Natural gas sold from the Company’s Methane Facility has been distributed and transported by pipeline. Electricity generated at the Company’s Methane Facility is distributed into the electric grid.

### Competitive Business Conditions, Competitive Position in the Industry and Methods of Competition

The Company’s contemplated oil and gas exploration activities in the State of Kansas will be undertaken in a highly competitive and speculative business atmosphere. In seeking any other suitable oil and gas properties for acquisition, the Company will be competing with a number of other companies, including large oil and gas companies and other independent operators with greater financial resources. Management does not believe that the Company’s competitive position in the oil and gas industry will be significant as the Company currently exists.

There are numerous producers in the area of the Kansas Properties. Some of these companies are larger than the Company and have greater financial resources. These companies are in competition with the Company for lease positions in the known producing areas in which the Company currently operates, as well as other potential areas of interest.

Although management does not foresee any difficulties in procuring contracted drilling rigs, several factors, including increased competition in the area, may limit the availability of drilling rigs, rig operators and related personnel and/or equipment in the future. Such limitations would have a natural adverse impact on the profitability of the Company’s operations.

The Company anticipates no difficulty in procuring well drilling permits in any state. The Company generally does not apply for a permit until it is actually ready to commence drilling operations.

The prices of the Company’s products are controlled by the world oil market and the United States natural gas market. Thus, competitive pricing behaviors are considered unlikely; however, competition in the oil and gas exploration industry exists in the form of competition to acquire the most promising acreage blocks and obtaining the most favorable process for transporting the product.

### Sources and Availability of Raw Materials

Excluding the development of oil and gas reserves and the production of oil and gas, the Company’s operations are not dependent on the acquisition of any raw materials.

### Dependence on One or a Few Major Customers

At present, crude oil from the Kansas Properties is being purchased at the well and trucked by Coffeyville Refining and NCRA, which are responsible for transportation of the crude oil purchased. The Company may sell some or all of its production to one or more additional refineries in order to maximize revenues as purchase prices offered by the refineries fluctuate from time to time.

In 2014, no gas was produced or sold from the Methane Project. If any gas is produced from the Methane Project in the future, the Company is dependent upon a small number of customers for the sale of gas from the Methane Project. These customers are principally gas marketing companies, utility districts, and industrial customers in the Kingsport area with which the Company may enter into gas sales contracts.

### Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts, Including Duration

On October 19, 2010, the Company’s subsidiary MMC was granted United States Patent No. 7,815,713 for Landfill Gas Purification Method and System, pursuant to application filed January 10, 2007. The patent term is for twenty years from filing date plus adjustment period of 595 days due to the length of the review process resulting in grant of the patent. The patent is for the process designed and utilized by MMC at the Carter Valley landfill facility. The patent may result in a competitive advantage to MMC in seeking new projects, and in the receipt of licensing fees for other projects that may be using or wish to use the process in the future. However, the limited number of high Btu projects currently existing and operated by others, the variety of processes available for use in high Btu projects, and the effects of current gas markets and decreasing or inapplicable green energy incentives for such projects in combination cause the materiality of any licensing opportunity presented by the patent to be difficult to determine or estimate, and thus the licensing fees from the patent, if any are received, may not be material to the Company’s overall results of operations.

### Need For Governmental Approval of Principal Products or Services

None of the principal products offered by the Company require governmental approval, although permits are required for drilling oil or gas wells.

### Effect of Existing or Probable Governmental Regulations on Business

Exploration and production activities relating to oil and gas leases are subject to numerous environmental laws, rules and regulations. The Federal Clean Water Act requires the Company to construct a fresh water containment barrier between the surface of each drilling site and the underlying water table. This involves the insertion of steel casing into each well, with cement on the outside of the casing. The Company has fully complied with this environmental regulation, the cost of which is approximately $10,000 per well.

As part of the Company’s purchase of the Kansas Properties, the Company acquired a statewide permit to drill in Kansas. Applications under such permit are applied for and issued within one to two weeks prior to drilling. At the present time, the State of Kansas does not require the posting of a bond either for permitting or to insure that the Company’s wells are properly plugged when abandoned. All of the wells in the Kansas Properties have all permits required and the Company believes that it is in compliance with the laws of the State of Kansas.

The Company’s exploration, production and marketing operations are regulated extensively at the federal, state and local levels. The Company has made and will continue to make expenditures in its efforts to comply with the requirements of environmental and other regulations. Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs. These regulations affect the Company’s operations and limit the quantity of hydrocarbons it may produce and sell. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments. The Company’s operations are also subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. For example, in May 2014 the Company become subject to regulations under the federal Endangered Species Act relating to the protection of the lesser prairie chicken as a threatened species. To avoid stringent penalties for violation of those regulations, the Company entered into a state-operated voluntary agreement avoiding those penalties provided certain protective methods are followed in drilling operations and remediation fees are paid by the Company for any wells determined to be likely to interfere with the habitat of the threatened species. These fees may increase the Company’s costs to drill in Kansas by approximately $40,000 per well. The Company owns or leases, and has in the past owned or leased, properties that have been used for the exploration and production of oil and gas and these properties and the wastes disposed on these properties may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and Recovery Act, the Federal Water Pollution Control Act and analogous state laws. Under such laws, the Company could be required to remove or remediate previously released wastes or property contamination.

Laws and regulations protecting the environment have generally become more stringent and, may in some cases, impose “strict liability” for environmental damage. Strict liability means that the Company may be held liable for damage without regard to whether it was negligent or otherwise at fault. Environmental laws and regulations may expose the Company to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and criminal penalties.

While management believes that the Company’s operations are in substantial compliance with existing requirements of governmental bodies, the Company’s ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. The Company’s current permits and authorizations and ability to get future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased costs or delays in receiving appropriate authorizations.

The Company maintains an Environmental Response Policy and Emergency Action Response Policy Program. A plan was adopted which provides for the erection of signs at each well containing telephone numbers of the Company’s office. A list is maintained at the Company’s office and at the home of key personnel listing phone numbers for fire, police, emergency services and Company employees who will be needed to deal with emergencies.

The foregoing is only a brief summary of some of the existing environmental laws, rules and regulations to which the Company’s business operations are subject, and there are many others, the effects of which could have an adverse impact on the Company. Future legislation in this area will be enacted and revisions will be made in current laws. No assurance can be given as to the affect these present and future laws, rules and regulations will have on the Company’s current and future operations.

### Research and Development

None.

### Number of Total Employees and Number of Full-Time Employees

The Company presently has 17 full time employees and no part-time employees. These employees are located in Colorado, Kansas, Tennessee, and Texas.

### Available Information

The Company is a reporting company, as that term is defined under the Securities Acts, and therefore files reports, including Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K such as this Report, proxy information statements and other materials with the Securities and Exchange Commission (“SEC”). You may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington D.C. 20549 upon payment of the prescribed fees. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

In addition, the Company is an electronic filer and files its Reports and information with the SEC through the SEC’s Electronic Data Gathering, Analysis and Retrieval system (“EDGAR”). The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically through EDGAR with the SEC, including all of the Company’s filings with the SEC. These may be read and printed without charge from the SEC’s website. The address of that site is www.sec.gov.

The Company’s website is located at www.tengasco.com. On the home page of the website, you may access, free of charge, the Company’s Annual Report on Form 10-K. Under the Investor Information /SEC filings tab you will find the Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Section 16 filings (Form 3, 4 and 5) and any amendments to those reports as reasonably practicable after the Company electronically files such reports with the SEC. The information contained on the Company’s website is not part of this Report or any other report filed with the SEC.

## Risk factors

As filed, 37,374 characters.

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. The risk factors described below are not exhaustive and you are encouraged to perform your own investigation with respect to the Company and its business. You should also read the other information included in this Form 10-K, including the financial statements and related notes.

**The Company’s indebtedness, global recessions, or disruption in the domestic and global financial markets could have an adverse effect on the Company’s operating results and financial condition.**

As of December 31, 2014, the outstanding principal amount of the Company’s indebtedness under its credit facility with Prosperity Bank (formerly F&M Bank & Trust Company) was approximately $734,000. Although the Company’s indebtedness has been substantially reduced, the current or an increased level of indebtedness, coupled with domestic and global economic conditions, the associated volatility of energy prices, and the levels of disruption and continuing relative illiquidity in the credit markets may, if continued for an extended period, have several important and adverse consequences on the Company’s business and operations. For example, any one or more of these factors could (i) make it difficult for the Company to service or refinance its existing indebtedness; (ii) increase the Company’s vulnerability to additional adverse changes in economic and industry conditions; (iii) require the Company to dedicate a substantial portion or all of its cash flow from operations and proceeds of any debt or equity issuances or asset sales to pay or provide for its indebtedness; (iv) limit the Company’s ability to respond to changes in our businesses and the markets in which we operate; (v) place the Company at a disadvantage to our competitors that are not as highly leveraged; or (vi) limit the Company’s ability to borrow money or raise equity to fund our working capital, capital expenditures, acquisitions, debt service requirements, investments, general corporate activity or other financing needs. The Company continues to closely monitor the disruption in the global financial and credit markets, as well as the significant volatility in the market prices for oil and natural gas. As these events unfold, the Company will continue to evaluate and respond to any impact on Company operations. The Company has and will continue to adjust its drilling plans and capital expenditures as necessary. However, external financing in the capital markets may not be readily available, and without adequate capital resources, the Company’s drilling and other activities may be limited and the Company’s business, financial condition and results of operations may suffer. Additionally, in light of the credit markets and the volatility in pricing for oil and natural gas, the Company’s ability to enter into future beneficial relationships with third parties for exploration and production activities may be limited, and as a result, may have an adverse effect on current operational strategy and related business initiatives.

**Agreements Governing the Company’s Indebtedness may Limit the Company’s Ability to Execute Capital Spending or to Respond to Other Initiatives or Opportunities as they May Arise.**

Because the availability of borrowings by the Company under the terms of the Company’s amended and restated credit facility with Prosperity Bank is subject to an upper limit of the borrowing base as determined by the lender’s calculated estimated future cash flows from the Company’s oil and natural gas reserves, the Company expects any sharp decline in the pricing for these commodities, if continued for any extended period, would very likely result in a reduction in the Company’s borrowing base. A reduction in the Company’s borrowing base could be significant and as a result, would not only reduce the capital available to the Company but may also require repayment of principal to the lender under the terms of the facility. Additionally, the terms of the Company’s amended and restated credit facility with Prosperity Bank restrict the Company’s ability to incur additional debt. The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, and dividends, voluntary redemptions of debt, investments, and asset sales. In addition, the credit facility requires that the Company maintain compliance with certain financial tests and financial covenants. If future debt financing is not available to the Company when required as a result of limited access to the credit markets or otherwise, or is not available on acceptable terms, the Company may be unable to invest needed capital for drilling and exploration activities, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt. In addition, the Company may be forced to sell some of the Company’s assets on an untimely basis or under unfavorable terms. Any of these results could have a material adverse effect on the Company’s operating results and financial conditions.

**The Company’s Borrowing Base under its Credit Facility May be Reduced by the Lender.**

The borrowing base under the Company’s revolving credit facility will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices. Reductions in estimates of the Company’s natural gas and crude oil reserves could result in a reduction in the Company’s borrowing base, which would reduce the amount of financial resources available under the Company’s revolving credit facility to meet its capital requirements. Such a reduction could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lender’s practices regarding estimation of reserves. If either cash flow from operations or the Company’s borrowing base decreases for any reason, the Company’s ability to undertake exploration and development activities could be adversely affected.

As a result, the Company’s ability to replace production may be limited. In addition, if the borrowing base is reduced, it would be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This requirement could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility.

**The Company’s Credit Facility is Subject to Variable Rates of Interest, Which Could Negatively Impact the Company.**

Borrowings under the Company’s credit facility with Prosperity Bank are at variable rates of interest and expose the Company to interest rate risk. If interest rates increase, the Company’s debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and the Company’s income and cash flows would decrease. The Company’s credit facility agreement contains certain financial covenants based on the Company’s performance. If the Company’s financial performance results in any of these covenants being violated, Prosperity Bank may choose to require repayment of the outstanding borrowings sooner than currently required by the agreement.

**Declines in Oil or Gas Prices Have and Will Materially Adversely Affect the Company’s Revenues.**

The Company’s financial condition and results of operations depend in large part upon the prices obtainable for the Company’s oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. As seen in recent years, prices for oil and natural gas are subject to extreme fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the Company’s control. These factors include worldwide political instability (especially in the Middle East and other oil producing regions), the foreign supply of oil and gas, the price of foreign imports, the level of drilling activity, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels, speculating activities in the commodities markets, and the overall economic environment. The Company’s operations are substantially adversely impacted as oil prices decline. Lower prices dramatically affect the Company’s revenues from its drilling operations. Further, drilling of new wells, development of the Company’s leases and acquisitions of new properties are also adversely affected and limited. As a result, the Company’s potential revenues from operations as well as the Company’s proved reserves may substantially decrease from levels achieved during the period when oil prices were much higher. There can be no assurances as to the future prices of oil or gas. A substantial or extended decline in oil or gas prices would have a material adverse effect on the Company’s financial position, results of operations, quantities of oil and gas that may be economically produced, and access to capital. Oil and natural gas prices have historically been and are likely to continue to be volatile.

This volatility makes it difficult to estimate with precision the value of producing properties in acquisitions and to budget and project the return on exploration and development projects involving the Company’s oil and gas properties. In addition, unusually volatile prices often disrupt the market for oil and gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties.

**Risk in Rates of Oil and Gas Production, Development Expenditures, and Cash Flows May Have a Substantial Impact on the Company’s Finances.**

Projecting the effects of commodity prices on production, and timing of development expenditures include many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved and other reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates, which would have a significant impact on the Company’s financial position.

### The Company Has a History of Significant Losses.

During the early stages of the development of its oil and gas business, the Company had a history of significant losses from operations, in particular its development of the Swan Creek Field and the Company’s pipeline assets. In addition, the Company has recorded an impairment of its oil and gas properties during 2008, impairments of its pipeline assets during 2010 and 2012, and an impairment of its methane facility in 2014. As of December 31, 2014, the Company has an accumulated deficit of $23.6 million. The Company recorded net losses of $2.0 million in 2009, $1.7 million in 2010, $0.1 million in 2012, and $0.8 million in 2014. In the event the Company experiences losses in the future, those losses may curtail the Company’s development and operating activities.

**The Company’s Oil and Gas Operations Involve Substantial Cost and are Subject to Various Economic Risks.**

The Company’s oil and gas operations are subject to the economic risks typically associated with exploration, development, and production activities, including the necessity of making significant expenditures to locate or acquire new producing properties or to drill exploratory and developmental wells. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations, and accidents may cause the Company’s exploration, development, and production activities to be unsuccessful. This could result in a total loss of the Company’s investment in such well(s) or property. In addition, the cost of drilling, completing and operating wells is often uncertain.

**The Company’s Failure to Find or Acquire Additional Reserves Will Result in the Decline of the Company’s Reserves Materially From Their Current Levels.**

The rate of production from the Company’s Kansas oil properties generally declines as reserves are depleted. Except to the extent that the Company either acquires additional properties containing proved reserves, conducts successful exploration and development drilling, or successfully applies new technologies or identifies additional behind-pipe zones or secondary recovery reserves, the Company’s proved reserves will decline materially as production from these properties continues. The Company’s future oil and natural gas production is consequently highly dependent upon the level of success in acquiring or finding additional reserves or other alternative sources of production. Any decline in oil prices and any prolonged period of lower prices will adversely impact the Company’s future reserves since the Company is less likely to acquire additional producing properties during such periods. The lower oil prices have a chilling effect on new drilling and development as such activities become far less likely to be profitable. Thus, any acquisition of new properties poses a greater risk to the Company’s financial conditions as such acquisitions may be commercially unreasonable.

In addition, the Company’s drilling for oil and natural gas may involve unprofitable efforts not only from dry wells but also from wells that are productive but do not produce sufficient volumes to be commercially profitable after deducting drilling, operating, and other costs. Also, wells that are profitable may not achieve a targeted rate of return. The Company relies on seismic data and other technologies in identifying prospects and in conducting exploration activities. The seismic data and other technologies used do not allow the Company to know conclusively prior to drilling a well whether oil or natural gas is present or may be produced economically.

The ultimate costs of drilling, completing, and operating a well can adversely affect the economics of a project. Further drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures, accidents, adverse weather conditions, environmental and other governmental requirements and the cost of, or shortages or delays in the availability of drilling rigs, equipment, and services.

**The Company’s Reserve Estimates May Be Subject to Other Material Downward Revisions.**

The Company’s oil and natural gas reserve estimates may be subject to material downward revisions for additional reasons other than the factors mentioned in the previous risk factor entitled “The Company’s Failure to Find or Acquire Additional Reserves Will Result in the Decline of the Company’s Reserves Materially from their Current Levels.” While the future estimates of net cash flows from the Company’s proved reserves and their present value are based upon assumptions about future production levels, prices, and costs that may prove to be incorrect over time, those same assumptions, whether or not they prove to be correct, may cause the Company to make drilling or developmental decisions that will result in some or all of the Company’s proved reserves to be removed from time to time from the proved reserve categories previously reported by the Company.

This may occur because economic expectations or forecasts, together with the Company’s limited resources, may cause the Company to determine that drilling or development of certain of its properties may be delayed or may not foreseeably occur, and as a result of such decisions any category of proved reserves relating to those yet undrilled or undeveloped properties may be removed from the Company’s reported proved reserves. Consequently, the Company’s proved reserves of oil may be materially revised downward from time to time.

In addition, the Company may elect to sell some or all of its oil or gas reserves in the normal course of the Company’s business. Any such sale would result in all categories of those proved oil or gas reserves that were sold no longer being reported by the Company. In August 2013, the Company sold all of its Tennessee producing oil and gas assets resulting in removal of all Tennessee oil and gas reserves from the Company’s reported reserves.

**There is Risk That the Company May Be Required to Write Down the Carrying Value of its Natural Gas and Crude Oil Properties.**

The Company uses the full cost method to account for its natural gas and crude oil operations. Accordingly, the Company capitalizes the cost to acquire, explore for and develop natural gas and crude oil properties. Under full cost accounting rules, the net capitalized cost of natural gas and crude oil properties and related deferred income tax if any may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized. If net capitalized cost of natural gas and crude oil properties exceeds the ceiling limit, the Company must charge the amount of the excess, net of any tax effects, to earnings. This charge does not impact cash flow from operating activities, but does reduce the Company’s stockholders’ equity and earnings. The risk that the Company will be required to write-down the carrying value of natural gas and crude oil properties increases when natural gas and crude oil prices are low. In addition, write-downs may occur if the Company experiences substantial downward adjustments to its estimated proved reserves. An expense recorded in a period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable to the subsequent period.

Due to the low oil prices experienced since the quarter ended September 30, 2014, during 2015 the Company expects that ceiling test failures will occur, requiring the Company to write-down its oil and gas properties. If the Company assumes the oil price per barrel, before differentials, remains at $50 per barrel for the remainder of 2015, the Company would anticipate impairments of approximately $20 million during 2015. The actual amount of impairment will be primarily contingent upon the actual oil prices received during 2015.

**There is a Risk That the Company May Be Required to Write Down the Carrying Value of its Manufactured Methane Facilities.**

The Company’s Manufactured Methane facilities are subject to review for impairment whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the methane facility assets. Should this occur, the assets’ carrying amount will be reduced to its fair value and the excess over fair value net of any tax effects, will be charged to earnings. This expense may not be reversed in future periods. In 2014, the Company recognized a non-cash impairment of its Manufactured Methane facilities in the amount of $2.8 million ($1.7 million net of tax effect). The impairment resulted from the Company’s assessment that future cash flows, using historical costs and runtimes, were insufficient to recover the Manufactured Methane facilities’ net book value. The Manufactured Methane facilities were written down to fair value amount calculated from estimated discounted cash flows, as well as certain expressions of interest with regard to the purchase by outside parties of the Company’s Manufactured Methane facilities.

### Use of the Company’s Net Operating Loss Carryforwards May Be Limited.

At December 31, 2014, the Company had, subject to the limitations discussed in this risk factor, substantial amounts of net operating loss carryforwards for U.S. federal and state income tax purposes. These loss carryforwards will eventually expire if not utilized. In addition, as to a portion of the U.S. net operating loss carryforwards, the amount of such carryforwards that the Company can use annually is limited under U.S. tax laws. Uncertainties exist as to both the calculation of the appropriate deferred tax assets based upon the existence of these loss carryforwards, as well as the future utilization of the operating loss carryforwards under the criteria set forth under FASB ASC 740, Income Taxes. In addition, limitations exist upon use of these carryforwards in the event that a change in control of the Company occurs. There are risks that the Company may not be able to utilize some or all of the remaining carryforwards, or that deferred tax assets that were previously booked based upon such carryforwards may be written down or reversed based on future economic factors that may be experienced by the Company. The effect of such write downs or reversals, if they occur, may be material and substantially adverse.

**Shortages of Oil Field Equipment, Services or Qualified Personnel Could Adversely Affect the Company’s Results of Operations.**

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. The Company does not own any drilling rigs and is dependent upon third parties to obtain and provide such equipment as needed for the Company’s drilling activities. There have also been shortages of drilling rigs and other equipment when oil prices have risen. As prices increased, the demand for rigs and equipment increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. These shortages or price increases could adversely affect the Company’s profit margin, cash flow, and operating results or restrict the Company’s ability to drill wells and conduct ordinary operations.

**The Company has Significant Costs to Conform to Government Regulation of the Oil and Gas Industry.**

The Company’s exploration, production, and marketing operations are regulated extensively at the federal, state and local levels. The Company is currently in compliance with these regulations. In order to maintain its compliance, the Company has made and will continue to make substantial expenditures in its efforts to comply with the requirements of environmental and other regulations. Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights. These regulations affect the Company’s operations and limit the quantity of hydrocarbons it may produce and sell. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.

### The Company has Significant Costs Related to Environmental Matters.

The Company’s operations are also subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company owns or leases, and has owned or leased, properties that have been leased for the exploration and production of oil and gas and these properties and the wastes disposed on these properties may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and Recovery Act, the federal Water Pollution Control Act, the federal Endangered Species Act, and similar state laws. Under such laws, the Company could be required to remove or remediate wastes or property contamination.

Laws and regulations protecting the environment have generally become more stringent and, may in some cases, impose “strict liability” for environmental damage. Strict liability means that the Company may be held liable for damage without regard to whether it was negligent or otherwise at fault. Environmental laws and regulations may expose the Company to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and criminal penalties.

The Company’s ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. The Company’s current permits and authorizations and ability to get future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased cost or delays in receiving appropriate authorizations.

### Insurance Does Not Cover All Risks.

Exploration for and development and production of oil can be hazardous, involving unforeseen occurrences such as blowouts, fires, and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life or damage to property or to the environment. Although the Company maintains insurance against certain losses or liabilities arising from its operations in accordance with customary industry practices and in amounts that management believes to be prudent, insurance is not available to the Company against all operational risks.

**The Company’s Methane Extraction Operation from Non-conventional Reserves Involves Substantial Costs and is Subject to Various Economic, Operational, and Regulatory Risks.**

The Company’s operations in its existing project involving the extraction of methane gas from non-conventional reserves such as landfill gas streams, required investment of substantial capital and is subject to the risks typically associated with capital intensive operations, including risks associated with the availability of financing for required equipment, construction schedules, air and water environmental permitting, and locating transportation facilities and customers for the products produced from those operations which may delay or prevent startup of such projects. After startup of commercial operations, the presence of unanticipated pressures or irregularities in constituents of the raw materials used in such projects from time to time, miscalculations or accidents may cause the Company’s project activities to be unsuccessful. Although the technologies to be utilized in such projects are believed to be effective and economical, there are operational risks in the use of such technologies in the combination to be utilized by the Company as a result of both the combination of technologies and the early stages of commercial development and use of such technologies for methane extraction from non-conventional sources such as those to be used by the Company. This risk could result in total or partial loss of the Company’s investment in such projects. The economic risks of such projects include the marketing risks resulting from price volatility of the methane gas produced from such projects, which is similar to the price volatility of natural gas. This project is also subject to the risk that the products manufactured may not be accepted for transportation in common carrier gas transportation facilities, although the products meet specified requirements for such transportation, or may be accepted on such terms that reduce the returns of such projects to the Company. This project is also subject to the risk that the product manufactured may not be accepted by purchasers thereof from time to time and the viability of such projects would be dependent upon the Company’s ability to locate a replacement market for physical delivery of the gas produced from the project.

We have been granted one U.S. patent and have been granted a continuation patent application relating to certain aspects of our methane extraction technology. Our ability to license our technology is substantially dependent on the validity and enforcement of this patent. We cannot assure you that our patent will not be invalidated, circumvented or challenged, that the rights granted under the patents will provide us competitive advantages. In addition, third parties may seek to challenge, invalidate, circumvent or render unenforceable any patents or proprietary rights owned by or licensed to us based on, among other things: subsequently discovered prior art; lack of entitlement to the priority of an earlier, related application; or failure to comply with the written description, best mode, enablement or other applicable requirements. If a third party is successful in challenging the validity of our patent, our inability to enforce our intellectual property rights could materially harm our methane extraction business. Furthermore, our technology may be the subject of claims of intellectual property infringement in the future. Our technology may not be able to withstand third-party claims or rights against their use.

Any intellectual property claims, with or without merit, could be time-consuming, expensive to litigate or settle, could divert resources and attention and could require us to obtain a license to use the intellectual property of third parties. We may be unable to obtain licenses from these third parties on favorable terms, if at all. Even if a license is available, we may have to pay substantial royalties to obtain a license. If we cannot defend such claims or obtain necessary licenses on reasonable terms, we may be precluded from offering most or all of our technology and our methane extraction business may be adversely affected.

**The Company Faces Significant Competition with Respect to Acquisitions or Personnel.**

The oil and gas business is highly competitive. In seeking any suitable oil and gas properties for acquisition, or drilling rig operators and related personnel and equipment, the Company is a small entity with limited financial resources and may not be able to compete with most other companies, including large oil and gas companies and other independent operators with greater financial and technical resources and longer history and experience in property acquisition and operation.

**The Company Depends on Key Personnel, Whom it May Not be Able to Retain or Recruit.**

Certain members of present management and certain Company employees have substantial expertise in the areas of endeavor presently conducted and to be engaged in by the Company specifically including engineering and geology. To the extent that their services become unavailable, the Company would be required to retain other and additional qualified personnel to perform these services in technical areas upon which the Company is dependent to conduct exploration and production activities. The Company does not know whether it would be able to recruit and hire qualified and additional persons upon acceptable terms. The Company does not maintain “Key Person” insurance for any of the Company’s key employees.

**The Company’s Operations are Subject to Changes in the General Economic Conditions.**

Virtually all of the Company’s operations are subject to the risks and uncertainties of adverse changes in general economic conditions, the outcome of potential legal or regulatory proceedings, changes in environmental, tax, labor and other laws and regulations to which the Company is subject, and the condition of the capital markets utilized by the Company to finance its operations.

**Being a Public Company Significantly Increases the Company’s Administrative Costs.**

The Sarbanes-Oxley Act of 2002, as well as rules subsequently implemented by the SEC and listing requirements subsequently adopted by the NYSE MKT, the exchange on which the Company’s stock is traded, in response to Sarbanes-Oxley, have required changes in corporate governance practices, internal control policies and audit committee practices of public companies. Although the Company is a relatively small public company, these rules, regulations, and requirements for the most part apply to the same extent as they apply to all major publicly traded companies. As a result, they have significantly increased the Company’s legal, financial, compliance and administrative costs, and have made certain other activities more time consuming and costly, as well as requiring substantial time and attention of our senior management. The Company expects its continued compliance with these and future rules and regulations to continue to require significant resources. These rules and regulations also may make it more difficult and more expensive for the Company to obtain director and officer liability insurance in the future, and could make it more difficult for it to attract and retain qualified members for the Company’s Board of Directors, particularly to serve on its audit committee.

**The Company’s Chairman of the Board Beneficially Controls a Substantial Amount of the Company’s Common Stock and Has Significant Influence over the Company’s Business.**

Peter E. Salas, the Chairman of the Company’s Board of Directors, is the sole shareholder and controlling person of Dolphin Mgmt. Services, Inc. the general partner of Dolphin Offshore Partners, L.P. (“Dolphin”), which is the Company’s largest shareholder. At March 20, 2015, Mr. Salas individually and through Dolphin controls 21,057,492 shares of the Company’s common stock and had options granting him the right to acquire an additional 125,000 shares of common stock. His ownership and voting control of approximately 34% of the Company’s common stock gives him significant influence on the outcome of corporate transactions or other matters submitted to the Board of Directors or shareholders for approval, including mergers, consolidations, and the sale of all or substantially all of the Company’s assets.

### Shares Eligible for Future Sale May Depress the Company’s Stock Price.

At March 24, 2015, the Company had 60,842,413 shares of common stock outstanding of which 21,326,718 shares were held by officers, directors, and affiliates. In addition, options to purchase 855,250 shares of unissued common stock were granted under the Tengasco, Inc. Stock Incentive Plan all of which were vested at March 24, 2015.

All of the shares of common stock held by affiliates are restricted or controlled securities under Rule 144 promulgated under the Securities Act of 1933, as amended (the “Securities Act”). The shares of the common stock issuable upon exercise of the stock options have been registered under the Securities Act. Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of the common stock and could impair the Company’s ability to raise additional capital through the sale of equity securities.

**Future Issuance of Additional Shares of the Company’s Common Stock Could Cause Dilution of Ownership Interest and Adversely Affect Stock Price.**

The Company may in the future issue previously authorized and unissued securities, resulting in the dilution of the ownership interest of its current stockholders. The Company is currently authorized to issue a total of 100 million shares of common stock with such rights as determined by the Board of Directors. Of that amount, approximately 61 million shares have been issued. The potential issuance of the approximately 39 million remaining authorized but unissued shares of common stock may create downward pressure on the trading price of the Company’s common stock.

The Company may also issue additional shares of its common stock or other securities that are convertible into or exercisable for common stock for raising capital or other business purposes. Future sales of substantial amounts of common stock, or the perception that sales could occur, could have a material adverse effect on the price of the Company’s common stock.

**The Company May Issue Shares of Preferred Stock with Greater Rights than Common Stock.**

Subject to the rules of the NYSE MKT, the Company’s charter authorizes the Board of Directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of the Company’s common stock. Any preferred stock that is issued may rank ahead of the Company’s common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than the Company’s common stock.

## Properties

As filed, 13,518 characters.

### Property Location, Facilities, Size and Nature of Ownership.

The Company leases its principal executive offices, consisting of approximately 3,021 square feet located at 6021 S. Syracuse Way, Suite 117, Greenwood Village, Colorado at an initial rental of $3,965 per month, expiring in May 2017. The Company also leases an office in Hays, Kansas at a rental of $750 per month that is currently a month to month lease.

The Company carries insurance on its Kansas properties, methane facility, offices, vehicles, and office contents. As of December 31, 2014, the Company does not have an interest in producing or non-producing oil and gas properties in any state other than Kansas.

### Kansas Properties

The Kansas Properties as of December 31, 2014 contained 27,189 gross acres in central Kansas. Of these 27,189 gross acres, 14,230 acres were held by production and 12,959 acres were undeveloped.

Many of these leases are still in effect because they are being held by production. The Kansas leases provide for a landowner royalty of 12.5%. Some wells are subject to an overriding royalty interest from 0.5% to 9%. The Company maintains a 100% working interest in most of its wells and undrilled acreage in Kansas. The terms for most of the Company’s newer leases in Kansas are from three to five years.

During 2014, the Company drilled 9 gross wells and completed 1 well that was drilling at the end of 2013. All of these wells were operated by the Company and the Company has a working interest of 100% in each well. Of the 9 wells drilled in 2014, 4 of the wells were completed as producing wells.

All of the Company’s current reserve value, production, oil and gas revenue, and future development objectives result from the Company’s ongoing interest in Kansas. By using 3-D seismic evaluation on the Company’s existing locations, the Company has historically added proven direct offset locations and will continue using 3-D seismic evaluation techniques in the future.

### Tennessee Properties

The Company closed the sale of all its Tennessee oil and gas properties on August 16, 2013.

### Reserve and Production Summary

The following tables indicate the county breakdown of 2014 production and reserve values as of December 31, 2014.

### Production by County

| Area | Gross Production MBOE | Average Net Revenue Interest | Percentage of Total Oil Production |
| --- | ---: | ---: | ---: |
| Rooks County, KS | 116.5 | 0.824264 | 62.8% |
| Trego County, KS | 33.8 | 0.809680 | 18.2% |
| Ellis County, KS | 9.6 | 0.808810 | 5.2% |
| Barton County, KS | 6.9 | 0.818072 | 3.7% |
| Graham County, KS | 5.8 | 0.862460 | 3.1% |
| Russell County, KS | 3.9 | 0.855852 | 2.1% |
| Pawnee County, KS | 3.4 | 0.813759 | 1.8% |
| Rush County, KS | 2.7 | 0.864319 | 1.5% |
| Osborne County, KS | 1.7 | 0.591493 | 0.9% |
| Stafford County, KS | 1.3 | 0.716138 | 0.7% |
| **Total** | **185.6** |  | **100.0%** |

### Reserve Value by County Discounted at 10% (in thousands)

| Area | Proved Developed | Proved Undeveloped | Proved Reserves | % of Total |
| --- | ---: | ---: | ---: | ---: |
| Rooks County, KS | $22,400 | $2,533 | $24,933 | 61.7% |
| Trego County, KS | 6,356 | 1,023 | 7,379 | 18.3% |
| Graham County, KS | 1,376 | 1,732 | 3,108 | 7.7% |
| Ellis County, KS | 1,884 | - | 1,884 | 4.7% |
| Barton County, KS | 1,124 | - | 1,124 | 2.8% |
| Russell County, KS | 827 | - | 827 | 2.0% |
| Rush County, KS | 691 | - | 691 | 1.7% |
| Pawnee County, KS | 236 | - | 236 | 0.6% |
| Stafford County, KS | 102 | 74 | 176 | 0.4% |
| Osborne County, KS | 18 | 41 | 59 | 0.1% |
| **Total** | **$35,014** | **$5,403** | **$40,417** | **100.0%** |

31

### Reserve Analyses

The Company’s estimated total net proved reserves of oil and natural gas as of December 31, 2014 and 2013, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following tables. All of the Company’s reserves were located in the United States. These estimates were prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) of Dallas, Texas, and are part of their reserve reports on the Company’s oil and gas properties. LaRoche and its employees and its registered petroleum engineers have no interest in the Company and performed those services at their standard rates. LaRoche’s estimates were based on a review of geologic, economic, ownership, and engineering data provided to them by the Company. In accordance with SEC regulations, no price or cost escalation or reduction was considered. The technical persons at LaRoche responsible for preparing the Company’s reserve estimates meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the estimating and auditing of oil and gas reserves information promulgated by the Society of Petroleum Engineers. Our independent third party engineers do not own an interest in any of our properties and are not employed by the Company on a contingent basis.

### Total Proved Reserves as of December 31, 2014

|  | Producing | Non Producing | Undeveloped | Total |
| --- | ---: | ---: | ---: | ---: |
| Oil (MBbl) | 1,360 | 78 | 359 | 1,797 |
| Future net cash flows before income taxes discounted at 10% (in thousands) | $32,059 | $2,955 | $5,403 | $40,417 |

### Total Proved Reserves as of December 31, 2013

|  | Producing | Non-producing | Undeveloped | Total |
| --- | ---: | ---: | ---: | ---: |
| Oil (MBbl) | 1,465 | 110 | 465 | 2,040 |
| Future net cash flows before income taxes discounted at 10% (in thousands) | $34,440 | $4,868 | $8,548 | $47,856 |

32

Historically, all drilling has primarily been funded by cash flows from operations with supplemental funding provided by the Company’s credit facility. The Company’s Proved Undeveloped Reserves at December 31, 2014 included 27 locations as compared to 29 locations at December 31, 2013. During 2014, one of the PUDs contributing reserves of 12 MBbl that existed at December 31, 2013 was drilled and moved into proved developed reserves, 9 PUDs contributing reserves of 155 MBbl were dropped from the PUD reserves at December 31, 2014, and there was a 50 MBbl downward revision in PUD reserves. These reductions were partially offset by the addition of 8 PUD locations which contributed 111 MBbl of reserves at December 31, 2014. Of the 9 locations that were dropped from the PUD reserves, 6 of these locations were dropped since they reached the 5 year limit that the Company is allowed to carry specific locations as a PUD reserve. The future development cost related to the Company’s Proved Undeveloped locations at December 31, 2014 was approximately $8.7 million. The Company intends to fund the drilling of these locations through operating cash flow and, as needed, supplement the funding by drawing on the Company’s credit facility. All proved undeveloped reserves included in the Company’s report at December 31, 2014 and 2013 are related to oil prospects in Kansas. During 2013, approximately 16.7 MBbl of proved undeveloped reserves that existed at December 31, 2012 were converted into proved developed reserves.

The oil price after basis adjustments used in our December 31, 2014 reserve valuation was $88.34 per Bbl compared to $90.11 per Bbl used in our December 31, 2013 reserve valuation. The primary factors causing the decrease in proved reserve volumes from December 31, 2013 levels were 2014 proved developed reserve additions not being significant enough to offset 2014 production as well as downward revisions of certain producing properties, recompletions and polymers, and proved undeveloped locations. (Refer to Note 15, Supplemental Oil and Gas Information, Standardized Measure of Discounted Future Net Cash Flows in the Company’s Notes to Consolidated Financial Statements for additional reserve information.)

The assumed prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect actual market prices for oil production sold after December 31, 2014. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.

In substance, the LaRoche Report used estimates of oil and gas reserves based upon standard petroleum engineering methods which include production data, decline curve analysis, volumetric calculations, pressure history, analogy, various correlations and technical factors. Information for this purpose was obtained from owners of interests in the areas involved, state regulatory agencies, commercial services, outside operators and files of LaRoche.

Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported in accordance with SEC rules and regulations as well as with established industry practices. The Company’s Exploration Manager and Petroleum Engineer each have extensive experience evaluating reserves on a well by well basis and on a company wide basis. Prior to generation of the annual reserves, management and staff meet with LaRoche to review properties and discuss assumptions to be used in the calculation of reserves. Management reviews all information submitted to LaRoche to ensure the accuracy of the data. Management also reviews the final report from LaRoche and discusses any differences from Management expectations with LaRoche.

### Production

The following tables summarize for the past three fiscal years the volumes of oil and gas produced from operated properties, the Company’s operating costs, and the Company’s average sales prices for its oil and gas. The net production volumes excluded volumes produced to royalty interest or other parties’ working interest. Tennessee amounts in 2013 represent results through August 16, 2013 when these properties were sold.

*Kansas*

| Years Ended December 31, | Gross Production Oil (MBbl) | Gas (MMcf) | Net Production Oil (MBbl) | Gas (MMcf) | Cost of Net Production (Per BOE) | Average Sales Price Oil (Bbl) | Gas (Per Mcf) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2014 | 185.6 | - | 152.2 | - | $31.77 | $86.05 | - |
| 2013 | 203.9 | - | 162.5 | - | $28.27 | $91.00 | - |
| 2012 | 278.8 | - | 225.9 | - | $22.48 | $86.90 | - |

*Tennessee*

| Years Ended December 31, | Gross Production Oil (MBbl) | Gas (MMcf) | Net Production Oil (MBbl) | Gas (MMcf) | Cost of Net Production (Per BOE) | Average Sales Price Oil (Bbl) | Gas (Per Mcf) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2013 | 3.8 | 51.3 | 2.7 | 37.9 | $28.90 | $92.66 | $3.94 |
| 2012 | 4.9 | 78.8 | 3.5 | 56.2 | $39.08 | $88.29 | $3.35 |

### Oil and Gas Drilling Activities

### Kansas

During 2014, the Company drilled 9 gross wells and completed 1 well that was drilling at the end of 2013. All of these wells were operated by the Company and the Company has a working interest of 100% in each well. Of the 9 wells drilled in 2014, 4 of the wells were completed as producing wells.

### Tennessee

In August 2013, the Company completed the sale of all its oil and gas producing and non-producing properties in Tennessee.

### Gross and Net Wells

The following tables set forth the fiscal years ending December 31, 2014, 2013 and 2012 the number of gross and net development wells drilled by the Company. The term gross wells means the total number of wells in which the Company owns an interest, while the term net wells means the sum of the fractional working interest the Company owns in the gross wells.

| Kansas | For Years Ending December 31, 2014 Gross | Net | 2013 Gross | Net | 2012 Gross | Net |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Productive Wells | 5 | 5 | 6 | 5 | 15 | 15 |
| Dry Holes | 5 | 5 | - | - | 5 | 5 |

### Productive Wells

As of December 31, 2014, the Company held a working interest in 215 gross wells and 209 net wells in Kansas. Productive wells are either producing wells or wells capable of commercial production although currently shut-in. One or more completions in the same bore hole are counted as one well. The term gross wells means the total number of wells in which the Company owns an interest, while the term net wells means the sum of the fractional working interests the Company owns in all of the gross wells. Tennessee productive wells were sold in August 2013.

### Developed and Undeveloped Oil and Gas Acreage

As of December 31, 2014 the Company owned working interests in the following developed and undeveloped oil and gas acreage. The term gross acres means the total number of acres in which the Company owns an interest, while the term net acres means the sum of the fractional working interest the Company owns in the gross acres, less the interest of royalty owners.

|  | Developed Gross Acres | Net Acres | Undeveloped Gross Acres | Net Acres | Total Gross Acres | Net Acres |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Kansas | 14,230 | 11,756 | 12,959 | 10,299 | 27,189 | 22,055 |

35

The following table identifies the number of gross and net undeveloped acres as of December 31, 2014 that will expire, by year, unless production is established before lease expiration or unless the lease is renewed.

|  | 2015 | 2016 | 2017 | Total |
| --- | ---: | ---: | ---: | ---: |
| Gross Acres | 2,486 | 3,200 | 7,273 | 12,959 |
| Net Acres | 2,073 | 2,547 | 5,679 | 10,299 |

## Legal proceedings

As filed, 546 characters.

The Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.

## Management's discussion and analysis

As filed, 30,226 characters.

### Results of Operations

The Company reported net loss from continuing operations of $(788,000) or $(0.01) per share in 2014 compared to net income from continuing operations of $3.0 million or $0.05 per share in 2013 and net income from continuing operations of $4.2 million or $0.07 per share in 2012. The Company did not report net income or loss from discontinued operations in 2014 as the Company’s pipeline assets were sold in August 2013. The Company did report a net loss from discontinued operations of $(0.14) million or $(0.00) per share in 2013 compared to a net loss from discontinued operations of $(4.3) million or $(0.07) per share in 2012. The net loss from discontinued operations in 2012 was primarily due to impairments of the Company’s pipeline assets in the amounts of approximately $3.4 million. Discontinued operations are net of associated taxes.

The Company realized revenues of approximately $13.8 million in 2014 compared to $15.7 million in 2013 and $20.6 million in 2012. During 2014, revenues decreased approximately $(1.9) million of which $1.2 million was related to decreases in oil sales volumes from 166.2 MBbl in 2013 to 153.5 MBbl in 2014. The more significant production declines were experienced in the Albers, Coddington, Liebenau, McElhaney A, Veverka A, and Veverka C leases. These decreases were primarily due to natural declines from higher levels of production as a result of drilling and polymers on these leases during 2011 and the first half of 2012. These production declines were partially offset by production from the successful drilling of the Albers B #3, Albers C #1, Howard A #1, and Veverka D #4 wells and recompletions of the Hammeke #3 and McElhaney #1 wells. In addition, $764,000 of this decrease related to a $4.98 per barrel decrease in the average oil price received from $91.03 per barrel received in 2013 to $86.05 per barrel received in 2014. Also, there was a $140,000 decrease related to lower gas sales as the Tennessee oil and gas assets were sold in 2013 and a $117,000 decrease in gas sales at the Methane facility as the Company focused on electric generation only in 2014. These decreases were partially offset by a $261,000 increase in electric generation revenues at the landfill related to an increase in runtime from 27% during 2013 to 56% during 2014. During 2013, revenues decreased $4.9 million of which $5.2 million related to decreases in oil sales volumes from 226.6 MBbl in 2012 to 166.2 MBbl in 2013. The more significant production declines were experienced in the Albers, Coddington, Hilgers B, Liebenau, McElhaney A, Veverka A, and Zerger A leases. These decreases were primarily due to higher 2012 production as a result of drilling and polymers on these leases during 2011 and the first half of 2012. In addition there was also a $(0.3) million decrease in sales from the Manufactured Methane facilities at the landfill related to increased downtime as a result of consistent high levels of oxygen in the landfill gas during 2013 which caused equipment to shut down until lower oxygen levels on a consistent basis were achieved. These decreases were partially offset by a $0.7 million increase related to a $4.11 per barrel increase in the average oil price received from $86.92 per barrel received in 2012 to $91.03 per barrel received in 2013. Gas prices received for sales of gas from the Swan Creek Field averaged $3.94 per Mcf in 2013, $3.35 per Mcf in 2012, and $4.28 per Mcf in 2011. Oil prices received for sales of oil from the Swan Creek field averaged $92.66 per barrel in 2013, $88.29 per barrel in 2012, and $87.33 per barrel in 2011. Swan Creek field results during 2013 reflect only operating from the beginning of 2013 until the field was sold in August 2013.

The Company’s production costs and taxes were approximately $6.0 million in 2014, $5.5 million in 2013, and $7.2 million in 2012. The $0.5 million increase in 2014 primarily related to a one-time $386,000 expense recorded during 2014 as a result of the IBLA affirmation of the civil penalty related to the 2012 Incident of Non-Compliance by the BSEE on one of Hoactzin’s properties, a $307,000 increase due to changes in oil inventory, and a $226,000 increase in well workover and repair cost primary related to work done on the Croffoot B #6 SWD, M. Rogers #2, H Karst SWD, Liebenau #8 and Wehrli #1 wells. These increases were partially offset by a $109,000 decrease in Swan Creek costs as these assets were sold in August 2013, a $185,000 decrease in Kansas property taxes related to natural declines as well as successful appeals, and a $68,000 decrease in landfill expenses primarily due to lower payroll costs. The $(1.7) million decrease in 2013 related primarily to a $(0.4) million decrease in Kansas property taxes primarily related to successful appeals of 2012 property taxes, $(0.2) million reduction in Gulf of Mexico related operating cost as the Management Agreement with Hoactzin expired in December 2012, $(0.2) million decrease in Manufactured Methane facilities costs, and $(0.2) million related to Swan Creek and pipeline asset cost as these were sold in August 2013.

Depreciation, depletion, and amortization were approximately $3.0 million in 2014, $2.9 million in 2013, and $3.4 million in 2012. The $118,000 increase in 2014 was primarily related to $448,000 due to an increase in the oil and gas depletion rate, a $26,000 increase in the methane facilities depreciation primarily related to capital spending in late 2013 and early 2014, partially offset by $(288,000) related to lower oil and gas sales volumes, and $(68,000) lower depreciation expense on other equipment due to the sale of the Tennessee oil and gas assets. The $(0.5) million decrease in 2013 was primarily related to lower oil and gas depletion expense due to lower sales volume partially offset by an increase in the depletion rate.

The Company’s general and administrative cost was approximately $2.7 million in 2014, $2.1 million in 2013, and $2.6 million in 2012. The $648,000 increase in 2014 was primarily related to $290,000 of costs incurred in 2014 for personnel, relocation cost, and office cost related to set up of the Denver office, a 2013 $98,000 reversal of a bad debt expense associated with the related party receivable, and $66,000 of consulting cost incurred in 2014 related to evaluating potential opportunities and review of the methane facility. The $(554,000) decrease in 2013 was a $(341,000) decrease in bad debt expense primarily as a result of recording in 2012 $257,000 of expense for Hoactzin-related receivables that was decreased by $(98,000) in 2013 as a portion of the related payables were paid and or re-billed to Hoactzin, and a $(199,000) decrease in legal, accounting, and consulting expenses. Compensation expense related to stock options was $32,000 in 2014 and was $(28,000) in 2013 and $52,000 in 2012. The 2013 amount was comprised of $32,000 of current year compensation expense offset by reversal of $59,500 previously recognized as compensation expense.

In 2014, the Company recorded a non-cash impairment of its Manufactured Methane facilities in the amount of $2.8 million ($1.7 million net of tax effect). The impairment resulted from the Company’s assessment that future cash flows, using historical costs and runtimes, were insufficient to recover the Manufactured Methane facilities’ net book value. The Manufactured Methane facilities were written down to fair value amount calculated from future discounted cash flows, using the same historical costs and runtimes, as well as certain expressions of interest with regards to the purchase by outside parties of the Company’s Manufactured Methane facilities. Although the Company believes the value realized from continued use of the Manufactured Methane facilities will be higher than the current carrying value, there can be no assurance that the Company will be able to increase runtime or reduce operating costs. Even if the Company is able to increase runtime and reduce operating cost, the impairment recorded in 2014 cannot be reversed in a later period.

In 2012, the Company recorded a non-cash impairment of its pipeline assets in the amount of $5.2 million ($3.4 million net of tax effect). The pipeline assets were classified as assets held for sale in the Company’s Consolidated Balance Sheet as of December 31, 2012. These write downs resulted from the Company’s assessment that cash flows generated from the pipeline were insufficient to recover the pipeline’s net book value. During 2012 and 2010, the Company received expressions of interest from potential purchasers of the pipeline asset which were significantly below the asset’s pre write down net book values. These expressions of interest indicated that the carrying amount of the pipeline may not be recoverable. At December 31, 2012, the Company was in the process of negotiating an agreement to sell the pipeline assets and the Swan Creek Field wells and associated equipment. Preliminary allocation of the sales value to the pipeline assets indicated a write down of approximately $5.2 million, before tax effect, was necessary. The pipeline asset was sold in August 2013.

Net interest expense was $88,000 in 2014, $357,000 in 2013, and $743,000 in 2012. The $(269,000) decrease in interest expense in 2014 was primarily due to a $4.4 million decrease in the average credit facility balance from $6.1 million during 2013 to $1.7 million during 2014. The decrease was primarily due to low drilling, recompletion, and polymer activities during 2014 resulting in operating cash flows in excess of drilling, recompletion, and polymer costs being used to pay down the credit facility. The $(386,000) decrease in interest expense in 2013 was primarily due to a $6.5 million decrease in the average credit facility balance from $12.6 million during 2012 to $6.1 million during 2013. The decrease was primarily due to low drilling and polymer activities during the second half of 2012 and all of 2013 resulting in operating cash flows in excess of drilling and polymer costs being used to pay down the credit facility.

During 2014 and 2013, the Company did not have any open derivative positions. During 2012, the Company recorded a $(0.14) million loss on derivatives. The 2012 loss on derivatives was comprised solely of an unrealized loss (See Item 7A. “Commodity Risk”).

The Company recorded income tax benefit on continuing operations of $6,000 in 2014, and income tax expense of $2.0 million in 2013, and $2.3 million in 2012. (See Note 14. Income Taxes in Notes to Consolidated Financial Statements)

Due to the low oil prices experienced since the quarter ended September 30, 2014, during 2015 the Company expects that ceiling test failures will occur, requiring the Company to write-down its oil and gas properties. If the Company assumes the oil price per barrel, before differentials, remains at $50 per barrel for the remainder of 2015, the Company would anticipate impairments of approximately $20 million during 2015. The actual amount of impairment will be primarily contingent upon the actual oil prices received during 2015.

### Liquidity and Capital Resources

At December 31, 2014, the Company had a revolving credit facility with Prosperity Bank (formerly F&M Bank & Trust Company). This is the Company’s primary source to fund working capital and future capital spending. Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $40 million or the Company’s borrowing base in effect from time to time. As of December 31, 2014, the Company’s borrowing base was $14.3 million. The borrowing base was reduced to $7.8 million with the March 16, 2015 amendment to the credit agreement. This reduction was primarily related to the significant decrease in the prices used by Prosperity Bank during their most recent borrowing base redetermination. The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities. The credit facility includes certain covenants with which the Company is required to comply. These covenants include leverage, interest coverage, and minimum liquidity ratios. During 2014, 2013, and 2012, the Company was in compliance with all covenants.

On March 27, 2014, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s semiannual review of the Company’s currently owned producing properties was amended to reduce the Company’s borrowing base from $17.5 million to $14.3 million and extend the term of the facility to January 27, 2016. The interest rate remained prime plus 0.50%.

On March 16, 2015, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s semiannual review of the Company’s then owned producing properties was amended to reduce the Company’s borrowing base from $14.3 million to $7.8 million and extend the term of the facility to January 27, 2017. The interest rate remained prime plus 0.50%.

The total borrowing by the Company under the facility at December 31, 2014 and December 31, 2013 was $734,000 and $3.3 million, respectively. The Company’s outstanding borrowing under the facility as of March 27, 2015 was approximately $843,000. The next borrowing base review will take place in July 2015.

Net cash provided by operating activities from continuing operations was $6.6 million in 2014, $8.0 million in 2013, and $9.3 million in 2012. Net cash used in operating activities from discontinued operations was $(85,000) in 2013 and $(265,000) in 2012. The decrease in cash provided by operating activities in 2014 was primarily related to a $(1.9 million) decrease due to lower oil volumes and prices, $(648,000) due to an increase in general and administrative expense, a $(470,000) decrease due to an increase in production costs and taxes, partially offset by a $1.2 million increase in cash provided by working capital. The decrease in cash provided by operating activities in 2013 was primarily related to a decrease in sales volumes, partially offset by increased oil prices, reduction in production costs and taxes, reduction in general and administrative costs and $1.3 million increase in cash flow provided by working capital. The increase in cash provided by operating activities from continuing operations in 2012 was primarily due to a $3.3 million increase related to increased sales volumes, partially offset by a $(1.3) million increase in production costs and taxes and a $(1.2) million decrease in changes in working capital. Cash flow provided by working capital was $1.4 million in 2014, and was $188,000 in 2013, and cash flow used in working capital was $(1.1) million in 2012. The primary difference in changes in working capital in 2014 as compared to 2013 was a $449,000 decrease in inventory, a $576,000 decrease in accounts receivable primarily due to lower December revenues and reduction of related party receivables, a $323,000 increase in accrued liabilities, and a $121,000 receipt of the refund of the certificate of deposit used to collateralize Tennessee plugging obligations, The difference in changes in working capital in 2013 as compared to 2012 was primarily posting cash collateral related to the appeal bond in 2012 and 2012 increase in equipment and materials inventory, partially offset by lower receivables in 2013 related to lower year-end revenues in 2013 as compared to 2012.

Net cash used in investing activities from continuing operations was $4.0 million in 2014, $2.2 million in 2013, and $7.6 million in 2012. The $1.8 million increase in cash used in investing activities during 2014 as compared to 2013 was due primarily to a $1.4 million increase in drilling and recompletion activities during 2014 as compared to 2013, and a $280,000 increase in Manufactured Methane facility costs primarily related to equipment and reconfiguration of the electric generator. The $5.4 million decrease in cash provided by investing activities in 2013 as compared to 2012 was due to decreased drilling and polymer activities in 2013 as compared to 2012, 2012 additions to the Manufactured Methane facilities, partially offset by the $1.0 million received in 2012 for payment in lieu of tax credits related to the Manufactured Methane facilities.

Net cash used in financing activities from continuing operations was $2.6 million in 2014, $5.7 million in 2013, and $1.8 million in 2012 resulting from excess cash flows from continuing operations used to pay down the Company’s credit facility. Net cash used in financing activities from discontinued operations in 2013 was $(1.3) million resulting in the sale of the Company’s pipeline assets. Net cash provided by financing activities from discontinued operations was $265,000 in 2012. This funding in 2012 was used to finance the Company’s pipeline operations.

### Critical Accounting Policies

The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which require the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. The Company considers the following policies to be the most critical in understanding the judgments that are involved in preparing the Company’s financial statements and the uncertainties that could impact the Company’s results of operations, financial condition and cash flows.

### Revenue Recognition

Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured. Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized. Natural gas meters are placed at the customer’s location and usage is billed each month. There were no natural gas imbalances at December 31, 2014 and 2013 as the Company sold its Tennessee oil and gas properties in August 2013. Methane gas and electricity sales meters are located at the Carter Valley landfill site and electricity generation sales are billed each month. No methane gas was sold during 2014.

### Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $462,000 and $736,000 in unevaluated properties as of December 31, 2014 and 2013, respectively. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down cannot be reversed in a later period.

### Oil and Gas Reserves/Depletion, Depreciation, and Amortization of Oil and Gas Properties

The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.

The Company’s proved oil and gas reserves as of December 31, 2014 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production, and timing of development expenditures includes many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.

### Asset Retirement Obligations

The Company’s asset retirement obligations relate to the plugging, dismantling, and removal of wells drilled to date. The Company follows the requirements of FASB ASC 410, “Asset Retirement Obligations and Environmental Obligations”. Among other things, FASB ASC 410 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. The Company currently uses an estimated useful life of wells ranging from 20-40 years. Management continues to periodically evaluate the appropriateness of these assumptions.

### Income Taxes

Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law. Temporary differences result principally from federal and state net operating loss carryforwards, differences in oil and gas property values resulting from a 2008 ceiling test write down, and differences in methods of reporting depreciation and amortization. Management routinely assesses the ability to realize our deferred tax assets and reduces such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be recognized.

At December 31, 2014, federal net operating loss carryforwards amounted to approximately $20.2 million which expire between 2019 and 2031. The total deferred tax asset was $7.35 million and $7.34 million at December 31, 2014 and 2013, respectively.

Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recovered.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.

The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized.

Although management considers our valuation allowance as of December 31, 2014 and 2013 adequate, material changes in these amounts may occur in the future based on tax audits and changes in legislation.

### Recent Accounting Pronouncements

In April 2014, the FASB issued ASU 2014-08 Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This guidance changes the criteria for reporting discontinued operations while enhancing disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. In addition, the new guidance requires expanded disclosures about discontinued operations that will provide financial statement user with more information about the assets, liabilities, income, and expenses of discontinued operations. This guidance is effective in the first quarter of 2015 for public companies with calendar year ends. The Company does not expect this to impact its operating results, financial position, or cash flows.

In June 2014, the FASB issued ASU 2014-12 Compensation – Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provided That a Performance Target Could Be Achieved after the Requisite Service Period. This guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718, Compensation – Stock Compensation, as it relates to awards with performance conditions that affect vesting to account for such awards. The performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. This guidance is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption in permitted. The Company does not expect this to impact its operating results, financial position, or cash flows.

In August 2014, the FASB issued ASU 2014-15 Presentation of Financial Statements – Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance is intended to define management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern and to provide related footnote disclosures. This also provides guidance to a organization’s management, with principles and definitions that are intended to reduce diversity in the timing and content of disclosures that are commonly provided by organizations today in the financial statement footnotes. This guidance is effective for annual periods beginning after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. Early adoption in permitted for annual and interim reporting periods for which the financial statements have not previously been issued. The Company does not expect this to impact its operating results, financial position, or cash flows.

### Contractual Obligations

The following table summarizes the Company’s contractual obligations due by period as of December 31, 2014 (in thousands):

| Contractual Obligations | Total | 2015 | 2016 | 2017 |
| --- | ---: | ---: | ---: | ---: |
| Long-Term Debt Obligations1 | $889 | $65 | $56 | $768 |
| Operating Lease Obligations | 120 | 48 | 50 | 22 |
| Estimated Interest on Long-Term Debt Obligations | 82 | 36 | 31 | 15 |
| Total | $1,091 | $149 | $137 | $805 |

## Market risk

As filed, 3,392 characters.

### Commodity Risk

The Company’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. Monthly oil price realizations during 2014 ranged from a low of $52.64 per barrel to a high of $98.51 per barrel.

In addition, during 2010, 2011, and 2012 the Company participated in derivative agreements on a specified number of barrels of oil of its production. The Company did not participate in any derivative agreements during 2014 or 2013, but may participate in derivative activities in the future.

### Interest Rate Risk

At December 31, 2014, the Company had debt outstanding of approximately $889,000 including, as of that date, $734,000 owed on its credit facility with Prosperity Bank. The interest rate on the credit facility is variable at a rate equal to the prime rate plus 0.50%. This rate was 3.75% at December 31, 2014. The Company’s remaining debt of $155,000 has fixed interest rates ranging from 3.9% to 7.25%. As a result, the Company annual interest cost in 2014 fluctuated based on short-term interest rates on approximately 82.6% of its total debt outstanding at December 31, 2014. During 2014, the Company paid approximately $71,000 of interest on the Prosperity Bank line of credit. The impact on interest expense and the Company’s cash flows of a 10% increase in the interest rate on the Prosperity Bank credit facility would be approximately $3,000 assuming borrowed amounts under the credit facility remained at the same amount owed as of December 31, 2014. The Company did not have any open derivative contracts relating to interest rates at December 31, 2014.

### Forward-Looking Statements and Risk

Certain statements in this Report including statements of the future plans, objectives, and expected performance of the Company are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which would cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.

1 The credit facility maturity date of January 27, 2017 is based on the March 16, 2015 amendment to the credit agreement.

There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology, and other factors can also affect these risks. Additionally, fluctuations in oil and gas prices or prolonged periods of low prices may substantially adversely affect the Company’s financial position, results of operations, and cash flows.

## Controls and procedures

As filed, 5,398 characters.

The Company’s Chief Executive Officer and Chief Financial Officer, and other members of management have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on such evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were adequate and effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Michael J. Rugen, the Company’s Chief Financial Officer is currently also serving as Company’s Chief Executive Officer on an interim basis. Mr. Rugen is acting in both capacities and has executed the accompanying certifications as to both offices.

The effectiveness of a system of disclosure controls and procedures is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of internal controls, and fraud. Due to such inherent limitations, there can be no assurance that any system of disclosure controls and procedures will be successful in preventing all errors or fraud, or in making all material information known in a timely manner to the appropriate levels of management.

### Managements Annual Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934. Internal control over financial reporting refers to the process designed by, or under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer, and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

- Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets;
- Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of the Company’s management and directors; and
- Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company internal control over financial reporting as of December 31, 2014. In making this assessment, the Company’s management used the criteria set forth in the framework in “Internal Control-Integrated-Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). This framework was updated in 2013. Based on the evaluation conducted under the framework in “Internal Control- Integrated Framework,” issued by COSO the Company’s management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2014.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-K.

### Changes in Internal Control Over Financial Reporting

As part of a continuing effort to improve the Company’s business processes, management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures. During 2014, certain transactions that were previously reviewed by the former CEO and Audit Committee are now performed by a third party accounting group and are reviewed by the CFO. There have been no changes to the Company’s system of internal control over financial reporting during the year ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting.

Filed Mar 30, 2015.
Source: SEC EDGAR, the filing index for accession 0001140361-15-013485. Last ingested by Listed: Nov 4, 2026, 18:14 ET. No prices; not investment advice.